USGIF GotGeoint BlogUSGIF promotes geospatial intelligence tradecraft and a stronger community of interest between government, industry, academia, professional organizations and individuals focused on the development and application of geospatial intelligence to address national security objectives.

November 06, 2018

As a rule of thumb increasing electric power generation is closely coupled with economic expansion. Between 2005 and 2017 the U.S. economy as measured by real GDP expanded by about 20 % from $15 trillion to $18 trillion. New data from the U.S. Energy Information administration (EIA) reveals that over this same period, emissions from power generation dropped primarily because of flat demand which is evidence of a decoupling between economic growth and power generation.

Data from the EIA reveals that during this time US power generation remained flat, but the makeup of U.S. power generation changed significantly. Generation from natural gas now exceeds that from coal and generation from wind, solar and other renewable sources now exceeds hydroelectric generation.

With respect to emissions the change is even more impressive. In a business as usual scenario assuming that demand continued to increase as it had prior to 2005, energy intensity (the energy required to produce a dollar of GDP) had remained at its 2005 value, and the energy mix had remained at its 2005 value, the expected emissions from electric power generation would have been about 3,043 MMmt (million metric tonnes). In 2017 actual emissions were much less, about 1,744 MMmt. About half of the drop in emissions in 2017 compared to the projected business as usual emissions was due to less demand (654 MMmt). Since the economy expanded over this time this is attributable to a drop in energy intensity and is evidence of decoupling of economic growth from power generation. The other important factors were switching among fuels, primarily switching from coal to natural gas (329 MMmt) and replacing fossil fuels with non-hydro renewables (316 MMmt).

In 2017 actual emissions from power generation were 43% less than that projected in the business as usual scenario and 28% below 2005 emissions. This is important progress toward the Paris accord targets (which the U.S. has dropped out of) since emissions from electricity generation are about 28% of U.S. total emissions.

July 18, 2017

On April 14, 2017 Secretary of Energy Rick Perry issued a memorandum directing preparation of a study to examine whether the retirement of many baseload plants (mostly coal-fired) are premature and whether their retirement reduces grid resilience. The Secretary directed the Department of Energy to conduct a rigorous analysis to answer these questions. The final report is expected in a few weeks, but a draft has been obtained by Reuters.

Major drivers of retirement: High natural gas availability and low electricity demand

Based on an extensive review of the electric power system evolution and events over the past thirty years and analysis of DOE and other data sources using basic supply and demand principles, a preliminary draft of the study concluded that many baseload retirements are not premature because they are consistent with observed market forces, primarily low natural gas prices and lower than expected electricity demand. Environmental regulations, state policies and competition with renewables are minor factors that have exacerbated and accelerated these trends. Since 2002 most baseload power plant retirements were victims of over capacity and relatively high operating costs that often reflect the age of the plants. The first tranche of fossil fuel retirements occurred before the explosive growth of renewable generation over the past five years.

Costly environmental regulations and subsidized renewable generation have exacerbated and accelerated baseload plant retirements, but these factors played minor roles compared to the long-standing drop in electricity demand relative to expectations and years of low electricity prices driven by high natural gas availability. While coal and nuclear power used to provide the bulk of U.S. electricity, wholesale electricity prices have closely tracked natural gas prices for the past 15 years beginning about the time that shale gas and oil entered the scene. Low natural gas prices and the fact that new, high efficiency natural gas generation and the pipelines required to provide fuel could be built rapidly helped grow natural gas plants relative to coal and nuclear. Renewables didn't cause retirements - baseload retirements due to age, inefficiency, and inability to compete began appearing in the early 2000s well before any significant levels of wind and solar generation - but competition with renewables has exacerbated the problem.

Impact on grid reliability

Numerous technical studies for most regions of the nation indicate that significantly higher levels of renewable energy can be integrated without compromising system reliability.

PJM (Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia)

30%

Midwest

25%

ERCOT

California

50%

Eastern US

30%

Western US

33% (wind and solar), 40% (all renewables)

Hawaii

100%

National

50%

The study outlines four principal ways to maintain and enhance bulk power system reliability: technology, rules and standards, business practices and last and most expensively, using high levels of transmission and generation.

Technology advancements now enable wind plants to provide a full spectrum of balancing services. For example, Xcel Energy requires turbines to be on automatic generation control, which allows computerized control system to directly control wind generation output.

FERC, NERC, and the RTOs and ISOs have undertaken several initiatives to use rules, standards, and grid codes to modify requirements for both interconnectioning renewables and legacy power plants to improve reliability.

Bonneville Power Administration provides an example of how to integrate wind energy effectively using operational and business practices rather than bringing on more generation reserves. BPA dealt with the reliability risk by limiting the amount of transmission available to the wind fleet (control and curtailment), charging for using hydropower to balance wind generation, and setting a penalty rate to encourage accurate wind generation scheduling.

March 28, 2017

Emissions Associated with Electric Power Production

Methane represents 9.9 % of U.S. greenhouse gas emissions and is at least 20 more times more potent in warming the atmosphere than carbon dioxide.

It has been asserted that natural gas power plants, which are responsible for 21% of power generation in the US, produce 50% less emissions than coal-fired plants. However, in the past the amount of methane gas that is lost (vented or leaked) during production, distribution and in plants has not been included in the calculation. Now a new study suggests that methane emissions from power plants and refineries may be much larger than current estimates.

A recent EPA analysis doubled its previous estimates for the amount of methane gas that leaks from pipes and is vented from gas wells, which significantly changes the emissions picture. Methane (CH4) levels from hydraulic fracturing of shale gas were found to be 9,000 times higher than previously reported. Based on the new numbers, the median gas-powered plant in the United States is estimated to be 40 % cleaner than coal-fired plants, according to calculations ProPublica has made. In addition about half of the 1,600 gas-fired power plants in the US operate relatively inefficiently. In the past these plants were estimated to be 32 % cleaner than coal, but with the revised EPA estimates, these ~800 inefficient plants are estimated to produce 25 percent less emissions than coal.

But there is another issue. Methane is one of the more potent greenhouse gases for global warming, but it is not clear just how much more potent methane is than CO2. The EPA has estimated a factor of 21 times compared to carbon dioxide. But Robert Howarth, an environmental biology professor at Cornell University, has suggested that it is actually 72 times as powerful as carbon dioxide in terms of its warming potential. This is critical, because if the climate effect of methane from natural gas is 72 rather than 21 times that of carbon dioxide from burning coal, natural gas may even turn out to be worse than coal in terms of global warming. Howarth has suggested that the type of shale gas drilling taking place in Texas, New York and Pennsylvania generates particularly high emissions of methane and could be as dirty as coal.

New estimates of methane emissions from power plants

Now a new study reports on overflights of power plants and refineries and finds that methane emissions are much larger than current estimates. Power plants and oil refineries are large consumers of natural gas. The EPA has collected data contributed by operators and estimated the methane (CH4) emissions from these plants, but there is high uncertainty in these estimated. In this study an airborne chemistry lab was used to estimate the methane emissions from three gas-fired power plants and three oil refineries. The average methane emission rates were larger than than the operator-reported estimates by 21 to 120 times for the power plants and by 11 to 90 times for the refineries. By looking at the pattern of methane emissions compared to carbon dioxide (CO2) and water vapour, the researchers were able to determine that the methane emissions were primarily from non-combustion processes suggesting leaks and venting as the sources. Scaling these result to the national level suggests that methane emissions from these types of facilities are 4.4 to 42 times larger than current estimates. The results indicate that gas-fired power plants and oil refineries could contribute significantly to U.S. methane emissions. The estimated contribution of 0.61 teragrams of methane annually (Tg CH4/yr) is significant, representing about 2% of total U.S. annual emissions of methane of about 30 Tg CH4/yr.

A recently published study has assessed the spatial distribution of anthropogenic methane sources in the United States by combining comprehensive atmospheric methane observations, extensive spatial datasets, and a high-resolution atmospheric transport model. Based on the results of this analysis the authors conclude that the EPA underestimates methane emissions nationally by a factor of about 1.5. Generally the study found that methane emissions due to the animal husbandry and fossil fuel industries have larger greenhouse gas impacts than indicated by existing inventories.

One of the motivations from switching from coal to natural gas for these types of facilities is that natural gas delivers the same amount of energy but with significantly reduced emissions. But that does not take into account leaks and other processes releasing methane during production, distribution and within plants. These latest results further reduce the advantage of gas-fired over coal-fired power production.

A study by Robert W. Howarth, Renee Santoro, and Anthony Ingraffea has concluded that the emissions of methane from shale gas wells are between 30% and 100% more than methane emissions from conventional natural gas wells. The study estimates that between 3.6% to 7.9% of the methane from shale-gas production escapes to the atmosphere in venting and leaks over the lifetime of a well.

As a result the study found that the greenhouse gas (GHG) footprint for shale gas is greater than that for conventional gas or oil. When compared to coal, which is responsible for nearly 50% of electric power generation in the US, the GHG footprint of shale gas is estimated to be 20% to 100% greater than coal over a 20 year period. Over a 100 years, the study concludes that the GHG impact of shale gas is comparable to coal.

November 17, 2016

The International Energy Agency (IEA) has issued its annual World Energy Outlook 2016. The IEA has examined several scenarios. All the Paris COP21 climate pledges from 190 countries have been incorporated into its main scenario. (It does not include any assessment of what the Trump administration may do with respect to the COP21 committments made by the world's second largest emitter.) It has projected that this scenario will actually result in 2.7 °C of warming. A scenario, called the 450 Scenario, with a 50% probability of limiting global warming to 2 ° C was also examined.

In its main scenario which includes emission reductions from COP21 pledges, the IEA projects a 30% rise in global energy demand to 2040. In 2040 it is projected that 60% of all new power generation capacity will come from renewables. In 2040 renewables are projected to represent 37% of all power generation. By 2040 most renewables-based generation is projected to be competitive without subsidies. Solar PV is expected to see a further 40-70% reduction in cost by 2040 and onshore wind by an additional 10-25%. However, fossil fuel generation continues to be important. Natural gas consumption is projected to rise by 50%. Growth in coal use essentially stops while growth in nuclearpower is limited to China.

Energy-related CO2 emissions plateaued in 2015 mainly because of a 1.8% improvement in the energy intensity of the global economy. This is partly because a growing proportion of the $1.8 trillion currently invested in energy annually is directed to renewables. But the IEA projects that even with the COP21 commitments energy-related emissions will continue to grow by 0.5% per year.

It is projected that a cumulative $44 trillion in investment will be needed in the global energy supply over the next 15 years. 60% of this will go to oil, gas and coal extraction and supply, including power plants using these fuels, and nearly 20% to renewable energies. Another $23 trillion will be required for energy efficiency improvements. For comparison over the last 15 years, 70% of total energy supply investment went to fossil fuels. This scenario requires a significant reallocation of capital from fossil fuels to renewables. This is aided by dropping fossil fuel subsidies. In 2015 the value of fossil-fuel consumption subsidies dropped to $325 billion, down from $500 billion the previous year.

The IEA projects that the COP21 commitments will slow the projected rise in global energy-related CO2 emissions. However, it does not believe that this is enough to limit warming to less than 2 °C. The IEA's 450 Scenario, which is based on a 50 % probability of limiting warming to under 2 °C, requires a further major reallocation of investment capital going to the energy sector. A greater proportion of the $40 trillion in cumulative energy supply investment has to move from fossil fuels and towards renewables and other low carbon investments in nuclear and carbon capture and storage so that the share going to fossil fuels would drop to about a third. In addition, $35 trillion is needed for improvements in energy efficiency - that's $12 trillion more compared with the main scenario. The 450 Scenario implies that before the end of this century, the energy sector must become carbon-neutral. That means all residual emissions from fuel combustion are either captured and stored, or offset by technologies that remove carbon from the atmosphere.

October 14, 2016

Methane has the second-largest global radiative forcing impact of anthropogenic greenhouse gases after carbon dioxide. In addition to anthropogenic sources, mainly fossil fuels, livestock and waste, natural methane sources include the biosphere (wetlands, termites, oceans, wildfires, and wild animals), volcanoes and geothermal emissions, and geological seepage where large quantities of natural gas migrate from shallow or deep rocks and reservoirs to the surface along faults and fractured rocks.

Estimates of emissions have come under increasing scrutiny. A recent study assessed the spatial distribution of anthropogenic methane sources in the United States by combining comprehensive atmospheric methane observations, extensive spatial datasets, and a high-resolution atmospheric transport model. It was concluded that the US Environmental Protection Agency (EPA) underestimates methane emissions nationally by a factor of 1.5.

The concentration of methane in the atmosphere stabilized from about 1999 to 2007. But here is evidence that since 2007 it began rising again. A recent study suggests that the more than 30% increase in U.S. methane emissions over the 2002–2014 period could account for 30–60% of the global growth of atmospheric methane seen in the past decade.

In a study just published the global methane budget and the contribution of the fossil fuel industry to methane emissions has been reevaluated. The ratio of carbon-13 to carbon-12 provides a signature which helps identify the source of methane. Both global methane and methane carbon isotope (carbon-13) records were used to compile what is believed to be the largest isotopic methane source signature database, including fossil fuel, microbial and biomass-burning methane emission sources. Total fossil fuel methane emissions from the fossil fuel industry plus natural geological seepage are 60 to 110 % greater than current estimates. After accounting for natural geological seepage, it is found that methane emissions from natural gas, oil and coal production and their usage are 20 to 60 % greater than current estimates.

May 15, 2016

According to the Energy Information Administration (EIA) since 2005 renewables have risen from 8% of total electricity generation in the U.S. to 13% in 2015. In 2015 non-emitting sources, renewables and nuclear, provided a record 33% of overall U.S. electricity production. Roughly another third was generated by natural gas and a third by coal.

In March 2015, the United States submitted its Intended Nationally Determined Contribution (INDC) for GHG emissions reduction to the United Nations Framework Convention on Climate Change targetting emissions reduction of 26% to 28% below 2005 levels by 2025. Electricity generation is the largest source of emissions in the U.S. In 2015 according to the EIA carbon dioxide (CO2) emissions from electricity generation totaled 1,925 million tonnes, 21% below their 2005 level so the INDC goals appear achievable, at least for electric power.

The reduction in emissions is due to two factors, increased non-emitting energy sources with most of the increase attributable to wind and solar, and the replacement of coal with natural gas.

There are two reasons why energy produced with natural gas is less carbon intensive than coal. Coal plants consume more energy than a combined-cycle natural gas plant to produce the same amount of electricity. Secondly, coal's carbon content per unit of energy is nearly twice that of natural gas. The bottom line is that to generate the same amount of electricity, natural gas emits 40% of the carbon dioxide that would be emitted from a coal-fired unit.

May 14, 2016

The "levelized cost", which is the present value of the total cost of building and operating a generating plant over its financial life, aims at making the costs of different generation technologies comparable. The US Energy Information Administration (EIA) has developed a standard way of estimating levelized costs. The most recent estimates of the average values of levelized costs for generating technologies are for generating facilities brought online in 2020 as represented in the National Energy Modeling System (NEMS) for the Annual Energy Outlook 2015 (AEO2015) Reference case.

The levelized cost represents the per-kWh cost (in real dollars) of building and operating a generating plant over an assumed financial life and duty cycle. Key inputs to calculating levelized costs include overnight capital costs, fuel costs, fixed and variable operations and maintenance (O&M) costs, financing costs, transmission costs, and an assumed utilization rate (capacity factor) for each plant type. Plants typically built for peaking have a much lower capacity factor or utilization rate than a baseload plant. Renewable energy generation also typically has a a lower capacity factor because wind and sun are intermittent.

The LCOE values shown for each utility-scale generation technology are calculated based on a 30-year cost recovery period, using a real after tax weighted average cost of capital of 6.1%. In the AEO2015 reference case, 3 percentage points are added to the cost of capital when evaluating investments in greenhouse gas (GHG) intensive technologies like coal-fired power and coal-to-liquids (CTL) plants without carbon control and sequestration (CCS). In LCOE terms, the impact of the cost of capital adder is similar to that of an emissions fee of $15 per metric ton of carbon dioxide (CO2) when investing in a new coal plant without CCS, which is representative of the costs used by utilities and regulators in their resource planning. As a result, the LCOE values for coal-fired plants without CCS are higher than would otherwise be expected.

U.S. average levelized cost of electricity (LCOE) for plants entering service in 2020

(2013 $/MWh)

Dispatchable

Total system LCOE

Conventional coal

95.1

Natural Gas - Combined cycle

75.2

Natural Gas - Combustion turbine

141.5

Advanced nuclear

95.2

Geothermal

47.8

Biomass

100.5

Nondispatchable

Total system LCOE

Wind

73.6

Offshore wind

196.9

Solar PV

125.3

Solar thermal

239.7

Hydroelectric

83.5

Comparing the levelized costs for dfferent generation technologies shows that natural gas-fired combined cycle and wind are the cheapest way to generate power in many parts of the country (without access to geothermal energy), recognizing that the levelized cost of coal includes the potential future cost of carbon emissions.

There is considerable variation in different regions of the U.S. especially in the case of renewable energy sources. The EIA has calculated levelized costs for 22 regions across the U.S.

Nondispatchable

Min

Ave

Max

Wind

65.6

73.6

81.6

Offshore wind

169.5

196.9

269.8

Solar PV

97.8

125.3

193.3

Solar thermal

174.4

239.7

382.5

Hydroelectric

69.3

83.5

107.2

The interesting conclusions are that wind has achieved parity with natural gas in many parts of the country and solar PV has achieved grid parity in some parts of the country(within the assumptions of levelized costs). This represents a significant drop in the cost of non-hydro renewable energy over the past 5 years.

Technology

2016

2018

2020

Conventional coal

100.4

100.1

95.1

Natural gas - Combined cycle

83.1

67.1

75.2

Wind

149.3

86.6

73.6

Solar PV

396.1

144.3

125.3

Hydroelectric

119.9

90.3

83.5

When I blogged about levelized costs at the beginning of 2011, the cost of solar PV per MWh was significantly more expensive than any other generation technology. Even in 2013 solar PV was still almost 50% more expensive than conventional coal. But now in some parts of the U.S. it is as cheap as conventional coal, though not as cheap as natural gas combined cycle.

April 25, 2016

At the 16th Annual GITA Pacific Northwest Conference, John Himmel, Manager GIS, at FortisBC Energy gave an overview of a remarkable geospatial solution that FortisBC will be deploying this summer. It is a new online application service that will be available to those of the public who wish to apply for gas services. Customers will have access to a GIS map showing the location of FortisBC underground gas lines, which will enable them to know if gas is available at their location. If it is, they will be able to see the estimated costs and arrange for a FortisBC construction crew to come and connect their home or business. Since FortisBC receives about 50,000 calls for new service annually of which it is estimated that 2/3 can be responded to and new services scheduled by the online system, this represents a potentially large savings for FortisBC.

FortisBC's new service is remarkable for two reasons. First of all, displaying the location of utility underground infrastructure publicly is not common. I blogged about a water utility in North Shore City in New Zealand one of the few utilities that I am aware of that has made maps of its underground infrastructure publicly available.

Secondly, it requires high quality data about the location of FortisBC's gas infrastructure. Many utilities would be unable to deploy an online service application like this one, because they would not have sufficient confidence in the reliability of the information about the location of their underground infrastructure in their GIS to present is publicly.

FortisBC has been able to maintain high quality information about their underground infrastructure which has enabled them to be confident about deploying an online service application. As further evidence of the quality of FortisBC's information about its underground infrastructure, they average about 900 pipe locate tickets every day. These originate primarily from BC One Call and come from people who intend to excavate somewhere in FortisBC's service territory. Because FortisBC's data about the location of its underground infrastructure is so good, 95% of these requests are handled within 12 minutes and do not require a truck roll. Avoiding truck rolls for pipe locates represents another major source of savings arising from the quality of their GIS data.

There are many other benefits that are expected with the new online service application. It represents a new way to interact with customers. Like many utilities, FortisBC is forging a new relationship with its customers and is going beyond just sending a bill every month. The online system also ensures crew availability before scheduling a new hookup with the customer. The online system also provides a automatic sales lead for FortisBC sales folks to follow up on if gas is not available at the customer location or if providing the requested service is not simple. In addition for a significant number of new gas service installations, the customer is not prepared when the crew shows up. The gas hookup has to be rescheduled and this wastes the crew's valuable time. The new online system will send email reminders to the customer in advance, which will reduce the number of hookups that have to rescheduled because of customer unpreparedness. Finally, the online system creates internal efficiencies and productivity savings by simplifying and automating processes that are currently largely manual.

April 22, 2016

At the 16th Annual GITA Pacific Northwest Conference at the Boeing Future of Flight Museum in Mukilteo WA, David Steiger gave a fascinating presentation about one of the major problems arising from our poor knowledge about the location of underground infrastructure. Cross bores are gas, power or telecom cables and pipes that bisect sewer pipes. Horizontal directional drilling (HDD), percussion moles and plows are trenchless techniques used to install natural gas distribution and other utility lines. These boring drill heads can easily go through sewer pipes without the driller being aware of it. Since the location of underground sewer pipes, either main line or laterals connecting the main pipes to houses, are only poorly known, cross bores are widespread. Hydromax USA specializes in detecting and mapping cross bores. In their experience in high risk, densely populated areas, as many as 3 cross bores per mile of natural gas distribution mainline have been found. The average is about 0.4 cross bores per mile.

Cross bores are dangerous. A typical scenario is that the cross bore leads to an obstruction in a sewer pipe. If this is a lateral, the house owner calls a plumber. The plumber bores out the lateral with a sewer cleaning machine that has a head that can cut through tree roots, the typical source of backed up sewers, and telecom or electric power cables or gas pipes with ease. The first documented case of a gas main being cut happened in 1976 and the resulting gas explosion killed two people and seriously injured four more. According to Hydromax the highest claim paid for a single cross bore incident was reported at $30,000,000.

Hydromax USA uses a robotic device that travels down sewer pipes including laterals and identifies and records the location of cross bores. Whenever they are found, the responsible utility rolls a truck a fixes them. Finding these problems is big business. Hydromax estimates that in the U.S. the total market for identifying and geolocating cross bores is about $1 billion per year.

Increased recognition of the injury, death and damage caused from cross bores has resulted in federal and state regulatory action. For example, the U.S. Department of Transportation’s 2011 Pipeline and Hazardous Materials Safety Administration’s (PHMSA) requirements of Distribution Integrity Management Program (DIMP) is intended to increase the integrity of gas distribution systems.

This problem is so prevalent that the Cross Bore Safety Association has been formed. The CBSA is a community of industry professional that have joined together to address all aspects of utility cross bores for protection against loss of life, injury and property damage.

April 13, 2016

In the culmination of a court case running for seven years, a jury in Pennsylvania found that Cabot Oil & Gas Corporation had been negligent and had contaminated the drinking water of two families near Dimock, Pennsylvania. $4.24 million was awarded to the two families. Cabot began drilling and fracking the Marcellus shale formation near Dimock in 2008.

As I have blogged about, a series of ProPublica reports identified instances where it was claimed that ground water had been contaminated in drilling areas across the United States. The film Gasland showed examples of combustible tap water (methane in tap water) and other effects in drinking water attributed to fracking.

The serious concerns about hydraulic fracturing’s potential impact on drinking water, human health and the environment had become serious enough that Congress appropriated funding for the EPA to undertake a major study of hydraulic fracturing and its impact on drinking water.Needless to say there is a lot of money and jobs involved. Hence, the study was very controversial and the oil/gas companies did not cooperate. Based on the limited evidence the EPA was able to collect, the study's draft executive summary said that it had not found evidence of "systemic, widespread effects on drinking water". But even the study's Science Advisory Board (SAB) disagreed with the conclusion, saying the evidence did suggest a wider problem.

A recent study by academics from Stanford in a peer-reviewed journal (Environ. Sci. Technol.,March 29, 2016, DOI: 10.1021/acs.est.5b04970) has confirmed that fracking did pollute an aquifer in Pavillion, Wyoming. The authors state "that they have, for the first time, demonstrated impact to Underground Sources of Drinking Water (USDWs) as a result of hydraulic fracturing."

The U.S. is predicted to become the biggest oil producer in the world, ahead of Saudi. This is largely because of hydraulic fracturing (fracking) and other well stimulation techniques, both for natural gas and oil. There are over half a million natural gas wells in the U.S. "Unconventional oil and gas" as fracking is often referred to has become a significant part of the U.S. economy employing millions.

But the environmental cost of fracking remains uncertain. In 2005 Congress passed the Energy Policy Act of 2005, which was an omnibus energy bill (that among many other things changed daylight savings time in the US). Among the provisions of the bill was one (the so-called "Halliburton loophole") that exempted hydraulic fracturing from protections under the Clean Air Act, Clean Water Act, and Safe Drinking Water Act, which means that fracking has never been regulated at the federal level (EPA).

The 2005 bill, which was passed during the GW Bush administration, prevented the EPA from doing any assessment of the environmental impact of "wild west" drilling and fracking. However, in the last few years so many reports and two documentary films including Gasland have been circulating about water contamination from fracking that Congress authorized the EPA to do the study of the impact of fracking on drinking water quality.

Cabot Oil & Gas Corp. has asked the courts to set aside a jury’s recent verdict.